1. Field of the Invention
This invention relates to a protection and testing system for a wellhead piping trunkline.
2. Description of Related Art
A wellhead high integrity protection system (HIPS) protects flowlines connected to a wellhead from overpressure should a downstream block valve close. The pressure source can be the oil-bearing geologic formation pressure. This pressure is known as the wellhead shut in pressure and it is based on geologic parameters, it is continuous, it cannot be controlled, i.e., it cannot be “turned off” in the conventional sense of that term. Multiple automated block valves are required in series downstream of the wellhead pressure source so that in case one valve leaks or fails to close, another will function to do so.
Although the surface safety valves (SSV) generally used in these applications are extremely reliable, the worst case scenario is considered in the design of safety systems. This is known in the field of safety instrumentation as a design that provides hardware dangerous fault tolerance. In the SSV tight shutoff testing method, valves will not only close, but will actually provide positive shutoff against the constant wellhead pressure, i.e., there will be no detectable leakage. Two series valves are required to allow for a tight shutoff test and the system includes a vent valve between the two series shutdown valves and an intermediate array of pressure transmitting sensors. In certain arrangements of the apparatus and system all of the function components are in communication with, and directed by a safety logic solver (SLS). Command and data signals can be carried over wires or communicated wirelessly.
Electric submersible pump systems and related technologies have been adopted to improve oil/gas recovery when production from the reservoir has been diminished by prevailing reservoir conditions. Downhole electric submersible pumps (ESP) are utilized to lift oil and gas to the surface where they are received by a wellhead flowline system for transportation and distribution. The pipeline pressure, flow rate and numerous other variables are monitored at the wellhead in order to insure, among other things, the safe operation of the pipeline and distribution system downstream of the wellhead. In the immediate vicinity of the wellhead, conventional mechanical protection systems can include the use of thick-walled pipe having an appropriately high pressure rating to withstand the high pressures that can be generated by the ESP. In the interests of economy, the pipeline downstream of the wellhead is fabricated from pipes having a defined lower safe operating pressure range. Relatively thinner walled pipe is used in the flowline system.
One problem that the new downhole ESP production controller introduced was that although it provided the required pressure boost to keep the oil flowing, should an intermediate block valve close in the long network of flowlines and trunklines between an offshore production platform and the onshore gas oil separation plant (GOSP), the pressure would build in the piping network to the pump's fully-blocked discharge pressure which in some cases is much higher than the normal flowing pipeline pressure. A flowline network suited for normal operations may not have a sufficiently high pressure rating to withstand the fully-blocked pressure of the ESP. Therefore, a high integrity protection system is required to limit the pressure in downstream piping to safe levels.
Running downhole pumps against a blocked discharge is not a normal practice, but is considered the worst case scenario when designing associated safety systems. The downhole ESPs are electrically driven and control of the pump as a potential source of dangerous pressure is electrical.
In order to insure the maximum flowline pressure remains within safe operations, so-called high integrity protection systems, or HIPS, have been developed for various applications. The conventional safety design practice of the prior art has been to specify flowlines that transport produced oil/gas from wellheads with sufficient wall thickness to contain the fully-blocked discharge pressure under theoretically possible worst case conditions. However, this approach proved to be impractical with the introduction of electric submersible pumps that can produce a very high wellhead shut-in pressure greater than 3000 psi. One approach that has been adopted is to continuously monitor the downstream flowline pressure and cut the power supply to the ESP before the flowline pressure reaches a dangerous level.
It is also known in the prior art to provide sub-surface safety valves (SSSV) for the purpose of shutting in the well and testing of these types of valves has been disclosed for the purpose of ensuring that the wellhead shutdown system will function properly, as for example in U.S. Pat. No. 4,771,633.
Other systems have been disclosed to allow the electric submersible pump to continue to operate in a re-circulation mode in the event of an emergency that requires the well to be shut in. Such systems are disclosed in U.S. Pat. No. RE 32,343 and U.S. Pat. No. 4,354,554.
Systems are also known for use in conducting an emergency shut down test of safety shut-off valves. For example, U.S. Pat. No. 7,079,021 discloses an emergency shut-down device controller and sensors to provide data to the controller, the controller having a processor, a memory coupled to the processor and an auxiliary input, wherein an emergency shutdown test is stored in the memory, and the auxiliary input is adapted to receive a binary signal and sensor data. Routines are stored in the memory and are adapted to be executed on the processor to allow the emergency shutdown test to be performed in response to the receipt of a binary signal at the auxiliary input and to cause sensor data to be recorded in the memory during the emergency shutdown test.
The above-described problems and proposed solutions are directed to individual wellhead flowline systems. Parent patent application U.S. Ser. No. 11/977,204, which is incorporated herein by reference, provides a wellhead flowline protection system and method that utilizes the downhole ESP speed controller and an SSV to ensure that dangerous pressure levels are not reached and provides for functional safety testing of the wellhead system. However, a unique problem arises in the context of a group of wellheads that are connected to a common trunkline. The maximum risk reduction criteria allowances combined with the required functional testing and maintenance of each HIPS creates both a practical and a design limitation that does not allow for more than a predetermined number of HIPS along a particular trunkline.
It would be desirable to provide oil/gas operations that utilize electric submersible pumps with a wellhead flowline protection system that is capable of providing fully automated proof-testing and self-diagnostics for a plurality of wells without the need for shutting in the plural wells for the purpose of conducting the test. The “online” testing can be performed at a regular interval, e.g., quarterly, combined with full, shut-in system verification during periods where production is shut down for scheduled, routine maintenance, testing and/or inspection.
It is therefore an object of the present invention to provide a wellhead control system and a method for the continuous monitoring and automatic testing for potential faults in a flowline associated with a cluster of wells each pressurized by an electric submersible pump while continuing the operation of the ESPs.
A further object of the present invention is to provide a reliable, automated testing and shutdown system to replace the instrumented flowline protection systems of the prior art which require production to be interrupted, significant manpower and that are based upon complicated manual proof-testing requirements.
Another object of the invention is to provide a safety test procedure for a cluster of wells each having an ESP that can be performed without interrupting production by turning off the ESP.
Yet another object of the present invention is to eliminate the dependence on manual human intervention for proof-testing of the system by providing an automatic functional testing and diagnostic method and system.